Diamondback Energy Inc (FANG) 2013 Q1 法說會逐字稿

Good day ladies and gentlemen, and welcome to the Diamondback Energy first-quarter earnings call.

(Operator Instructions)

I would now like to introduce your host for today's program Adam Lawlis, Investor Relations.

Good morning, and welcome to Diamondback Energy's first-quarter conference call.

Again, my name is Adam Lawlis and I manage Investor Relations at Diamondback. Representing Diamondback today are Travis Stice, CEO; Tracy Dick, CFO; and Russell Pantemuehl, Vice President of Reservoir Engineering.

During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors.

Information concerning these factors can be found in the Company's filings with the SEC. During our call today we will reference certain non-GAAP financial measures, which we believe provide useful information for investors. We include reconciliations of those measures to GAAP in our earnings release.

I will now turn the call over to Travis Stice.

Thanks, Adam.

Welcome everyone and thank all of you for listening in to Diamondback's first-quarter 2013 conference call. When discussing quarter-over-quarter comparisons, I'll be referring to the pro forma numbers for 2012, which give effect to our acquisitions as if they had occurred at the beginning of 2012.

Over the past few months, Diamondback has continued to make significant progress in expanding on our horizontal drilling with 15 horizontal Wolfcamp B wells in various stages of development with what we feel are very exciting results. Our acreage lies right in the heart of this emerging play in the Midland basin, and we feel like we're leading the way in delivering horizontal well results to our stockholders. We've achieved an average 24-hour IP rate from eight horizontal wells of 836 BOEs per day, of which 87% is oil from lateral links that average just slightly less than 5000 feet with two marquee wells testing at rates exceeding 1,000 barrels a day equivalent. The average 30-day rate for this same set of wells was over 600 BOEs per day.

We are currently running two horizontal rigs, one in Upton and one in Midland county. Operationally, we've been active on several fronts, including ramping production and increase in efficiencies in an effort to achieve best in basin margins. Looking at results, we are pleased with our production for the first quarter of 2013, which averaged 4,800 BOEs per day. The production ramp we expected from horizontal wells was evident as we exited the quarter at 5,500 BOEs per day. This is almost 1,000 barrel a day increase when compared to 2012 exit rate of 4,500 BOEs per day.

Now looking just at the oil component of the production stream which accounts for 87% of our revenue, our first quarter exit rate for oil was up 38% compared to the fourth quarter, reflecting the high percentage of oil we've seen from these horizontal wells. Although the production ramp we developed last year for 2013 started roughly a month later than planned due to some production delays associated with our choice to gather data in a micro seismic fashion and an operational delay on our first horizontal well.

Both the vertical and horizontal wells are meeting or exceeding our expectations. Although the numbers are not finalized for April yet, our production is around for the month 6,000 BOEs per day, and when I'm looking at the first few days of May, we are over 6,500 BOEs per day. This production ramp gives us confidence in delivering on our growth profile for 2013.

Our operations team continues to improve performance to a level we believe is among the best in the Midland basin. We had a 7,500-foot lateral in Upton County that reached TD in 16.5 days, and a 4,500-foot well, also in Upton County, that reached TD in 13.5 days. Our first quarter well costs for short laterals was $6 million, which is a 22% improvement over the fourth quarter of last year and our longer laterals of 7,500 feet averaged $7.8 million for this quarter, which is, again a 10% improvement over the fourth quarter of last year.

We expect our well costs to migrate to the low end of our guidance of between $7.5 million to $8.5 million for these 7,500-foot lateral wells with further up side possible as we continue to optimize our completions. We also saw improvements again this quarter on our vertical program with spud to TD times decreasing by 18%, to average nine days. Three of these wells reached TD in less than eight days.

We plan to begin testing the horizontal potential of our Andrews County leasehold during the end of third-quarter 2013, with wells planned both in the Wolfcamp B and in the Clearfork shale intervals. Acreage values continue to increase as seen in the recent results of the University Lands Auction with offset acreage selling at over $6,500 per acre. Likely driven, we feel, by horizontal prospectivity. This acreage pricing reflects positively for our 18,000 net acres in Andrews County.

Now, as I said earlier, we've got 15 horizontal wells in various stages of development. Referring to our earnings release from yesterday, you can see all the details associated with each of these horizontal wells. The two best wells are from the Midland County, ST2501H that peaked at 1,054 BOEs per day and the Upton County Neal82H that peaked at 1,134 BOEs per day. The Spanish Trail 2501H result is particularly encouraging since that is a short lateral of only about 4,451 feet. Now we're currently flowing back our first 7,500-foot lateral well in Midland County and it's just now starting to produce oil.

When we evaluate our performance using the early time data for these horizontal wells, we are at or above our type curve projections. We are also encouraged by the strong results recently delivered by the pioneer operated horizontal Wolfcamp B hut well, which is located within 18 miles of our acreage in Midland county.

We believe our activity, combined with industry results, has essentially de-risked our leasehold in Midland and Upton counties and the Wolfcamp B target zone. Our first quarter LOE per BOE has decreased 20% to $12.61 per BOE when compared to the fourth quarter of 2012. This is being driven lower as we place more water into pipelines and less into truck carriers. While we are just beginning to benefit from infrastructure expenditures, we believe we are well on our way of our goal to reduce our total LOE to between $11 and $13 by the end of this year. This effort to reduce cost will continue, and expect me to report on our efforts each call.

We also expect to further improve our oil price realizations through our connection to the Magellan longhorn pipeline. Although our production is currently pro rated, in May we expect to move an estimated 1,422 gross barrels of oil per day into the pipeline, and we anticipate monthly increases in deliveries until at full pipeline capacity in late 3Q. At that point we expect to be delivering 8,000 gross barrels per day through the remainder of the five-year term.

If this pipeline had been operational during the first quarter of 2013, we would have increased our oil price realizations by $21 a barrel. Now, while we've seen this spread contract recently between LOS and WTI, we feel that having 8,000 barrels a day of non-interruptible transportation out of the Permian is a big advantage for our shareholders -- not only in the physical movement of oil -- but also improved price realizations if the basis differential widens again like we saw during the first quarter. And lastly, we have added -- we have continued to add liquidity to the balance sheet, as our borrowing base has increased 33% to $180 million.

With these comments complete, allow me to turn the call over to Tracy.

Thanks, Travis. Our net income for the quarter was $5.4 million or $0.15 per share. Net income for the period included an unrealized gain on commodity derivatives of $1.5 million. Excluding the unrealized gain and the related income tax effect, adjusted net income was $4.4 million, or $0.12 per diluted share. Revenues for the first quarter totaled $28.9 million as compared to fourth quarter of 2012 of $27 million.

Our sequential quarter-over-quarter $2 million increase is supported by higher price realizations and increased production volumes. The net dollar effect of the increases in both price and production was $0.9 million and $1.1 million respectively. Our average realized price before the effect of hedges was 6,709 per BOE compared to 6,396 per BOE for the prior quarter.

Our average realized price -- including the effect of hedges -- was 6,351 per BOE, compared to 6,143 for the prior quarter. EBITDA for the quarter was $20.3 million. Our LOE was $12.61 per BOE, as compared to $15.68 per BOE in the fourth quarter of '12. Our LOE per BOE is in line with our LOE guidance of between $11 and $13.

Our general and administrative costs came in at $5.73 per BOE. We expect unit costs to decline with higher volumes and trend toward our guidance of $3 to $5 per BOE in the second quarter. Our production tax and BD&A are both in line with guidance.

At quarter's end, we have $36.5 million in debt leaving $104 million of liquidity in the form of cash on hand and additional borrowing capacity. With our borrowing base redetermination recently completed, an increase to $180 million, our liquidity has increased by an additional $45 million. Our current debt -- outstanding today -- is $44 million. Our debt to capitalization ratio was 7% at the end of the quarter.

In the first three months of 2013, we generated $17 million of cash flow or $0.46 a share. We spent $74.1 million. This includes approximately $15 million for drilling and completion, $18.6 million to Gulfport for the final settlement of a post-closing tax adjustment in connection with the acquisition of their properties and the remainder on infrastructure, facilities, and acquisitions.

I'll now turn the call back over to Travis for his closing remarks.

Thanks, Tracy.

To summarize, and like I said in my opening comments, we are pleased with our performance during the first quarter this year. As we have migrated the Company to increase our horizontal development and we're well on our way to delivering our volume growth projections. We have ramped our production through these results on these horizontal wells. Our expenses are down. We are executing at or near the top in our anticipated drilling results. Development costs on both horizontal and vertical wells are trending down. And we have added liquidity with our increased borrowing base. We feel like we have the right assets and the right people to deliver on a very exciting 2013.

Now before I open the call to questions, please note that we filed an S1 registration statement with the SEC on April 11 in conjunction with the proposed follow on equity offering to raise the additional equity to accelerate horizontal activity. We are still in the filing process with the SEC and I may be precluded from answering some of your questions. On behalf of the Board and employees of Diamondback Energy, I would like to thank you for your participation today.

This concludes our prepared comments. Operator, please open the call to questions.

(Operator Instructions) Our first question comes from the line of Ryan Oatman with SunTrust.

Good morning, Travis.

Good morning, Ryan.

You mentioned you feel that Midland and Uptown County acreage is substantially de-risk -- Can your just remind us how much acreage you have in those two counties?

Yes, Ryan, good question. In Midland, we have got about 10,000 acres. And in Upton County we also have about 10,000 acres. And those are net acres.

Okay, great. And then shifting to Andrews County, what makes the Clearfork the attractive target there versus say the Wolfcamp B?

Well, if you noticed when I said Andrews County we're testing both. We're testing the Wolfcamp B on the eastern edge of Andrews County where we think the shale thickness and off set activity has really given us some excitement to test that zone. And as we move a little further west in Andrews County where we have got a large acreage block, the Clearfork shale looks really exciting.

We have done a lot of science on the Clearfork there including a vertical well test in the Clearfork shale only, which tested at 50 barrels a day. And we've also done some side well core analysis and some advanced shale logging. All of which indicate that this is a really prospective shale zone for us. Anywhere else we are watching offset operator activity as well, as they test the Clearfork shale and as you move kind of off the shale's edge into where our acreage is, that Clearfork gets deeper and thicker, which we think are both accretive to our acreage position.

Great. Thank you for that color there. And then, curious what you can tell us on this Kendra well, which is currently flowing back. Did you have any issues there? Do you feel like you had an effective stimulation, stated zone, et cetera, et cetera.

Yes, that well was effectively stimulated. It was our standard completion technique with roughly 300,000 pounds of sand per stage. It is sort of a long lateral. You can see the lateral length in our earnings release and it was drilled and completed without incident, and we have had it on now for a week and a half. It's 15% load recovery. And it's increasing oil every day. I think last night it made about 520 barrels of oil and still flowing at the casing.

Okay, great. And that 520, how does that compare to say, what you saw earlier in the Neil A or Neil B wells?

It is right in line, Ryan. It's tracking almost exactly.

Okay, very good. Appreciate all that. I will hop back in the queue.

Great, thanks, Ryan.

Our next question comes from the line of Gordon Douthat with Wells Fargo Securities. Your question please.

Morning, guys. Travis, you mentioned you are having success getting well costs down and you are tracking towards the low end of your targets, or you hope to be there by year end. Can you talk about some of the things you are seeing on both the drilling and completion side that is allowing you to realize these reductions?

Yes, specifically on the drilling side, what the drilling organization is doing is with the extreme focus on just almost every connection on the drill pipe, they have improved efficiency. So, they can tell you how many minutes it takes to make a connection. And so what that really translates to is a behavior that actually cuts days out of the total execution. When I talk about 16.5 day well that's out there at 7,500-feet, It's through a lot of hard work and diligence on the drilling side of the organization.

And then on the completion side, what these guys are doing is continue to optimize the completion methodology without sacrificing EUR or initial production rate. Specifically, what we're doing is we've tested with cutting out stages but still pumping the same amount of proppant and fluid, and what that really does is it cuts time out of the completion. And when you cut time out of the completion, you also cut dollars. So, when you combine all that together with the extreme focus on cost that we have, and on our execution, you start seeing the results we are seeing right now with quarter-over-quarter improvements.

Okay. That is good color. And can you get into maybe more specifics about your standard completion. I know you mentioned 300 pounds of prop in per stage. But as you complete these wells both on long and the short laterals, how do you look to space the frac stages and what type of completion recipe are you fracking these wells with?

You know, our current recipe is about 300,000 pounds per stage, and the inner stage distance is about 250 feet. And we're using slick water transport fluid and 40/70 sand, white sand.

Okay. And then just last question for me. You mentioned the B-bench looks to be de-risked. When do you think outside of Andrews, actually in Midland and Upton, when do you think you'll test other benches, the A or maybe the other benches?

Well, you know, we ask ourselves that question almost every day. And what's hard for us to try to justify is bringing on wells that are making 1,000 barrels a day to go test other benches. And really what I think we're doing right now is, there's a lot of industry activity that's been announced out there where other benches are being tested, and so I'm going to continue to try to keep my drillbit in the Wolfcamp B and I will follow very closely with the industry reports and these other benches. And we will be able to respond very quickly if somebody comes up with a zone that is better than a Wolfcamp B. But right now I am going to try to keep my drillbit in the Wolfcamp B there, in Midland County.

All right, makes sense. Thank you.

The next question comes from the line of Jason Wangler from Wunderlich Securities.

Good morning. Just one quick one on the CapEx side. The 18.6 to gulf port, assuming obviously that's the final settlement. Is there any other payments like that expected or I assume that is it? Is that baked into the current CapEx guidance? Just want to make sure that I am accounting for that right.

Sure. No further payments and yes, it is baked into our CapEx guidance.

That is all I had, thank you.

Thank you, our next question comes from the line of Jeb Bachmann from Howard Weil, your question please.

Going back to Travis going back to the your completion methods, can you tell us, talk about the differences that you are seeing between the submersible pumps and the gas lifts, on these horizontal Wolfcamp wells?

Sure, when we originally started with the gas list, we did that, one to sort of minimize operational risk. And two, we were looking at it to save an extra rig up. And rig up on one of these top wells typically runs around $25,000 to $30,000. And we avoided that by going to gas lift because we're drilling that with stick pipe, that is our standard method right now. And the reason we are drilling that with stick pipe is because as we test these longer 10,000-foot laterals, we know we cannot use coil to clean out that whole lateral.

We're building our game out to drill out the wells with stick pipe, which is what we are doing. What we do, when we already have a rig there since we're using stick pipe, we will just run in there with tubing and gas lift valves and let the well start producing the well up the tubing. If I let the well flow, I have to wait for it to flow, and then deplete on flow back and rig up again where the incremental cost comes in and put a sub pump on there.

Now, having said all of that. What we really did was we set up two test wells where we could measure them side by side. The 25-1H, which is on sub pump, and the 25-2H, which is on a gas lift, and what we are looking at, looking at the total cube production in the first 90-day period and get a gauge on whether or not the sub pumps are differentially better than the gas lift. But, I can tell you what we are seeing right now. These early rates it just appears that the sub pumps are capable of moving more fluid early on, that is early on, probably in the first 30 days, than the gas lift wells are. So our operations program is migrating towards more sub pumps.

Great, thanks. And one other clarification for me, Travis. On, you mentioned the 38% exit rate for oil increase over 1Q '13 over 4Q '12. Was that a 4Q '12 exit rate or the 4Q '12 average?

That was 4Q '12 exit rate.

Great, thanks, guys.

Thank you. Our next question comes from the line of John Freeman from Raymond James.

Good morning, guys. On the, your vertical -- the plans for the 35 to 40 gross vertical wells that's currently guided to. What spud to TD time does that assume?

I think for your planning purposes, kind of two wells per month on these vertical wells. We are averaging, like I said, in the first quarter, spud to TD of about nine days, gives us a day or so to run casing and a couple of days to move the rig. So, just from a planning purpose, I think you could go about two vertical wells per month.

Okay, yes, that is kind of what I was getting at. Looks like you are doing a little bit better on the days than what you originally budgeted for. And curious if we might see that vertical well count guidance maybe go up a little bit just because of the run rate?

Yes, that's a fair question. But right now for your planning purposes, I would just stay with two per month.

Okay, and then back on the completion side, on these horizontals, just to make sure I am understanding this correctly. You all have been testing the longer laterals so far at least you have stayed with a consistent 300,000 pounds of sand per stage. You haven't sort of adjusted to see if, as you go longer, maybe to increase that?

Well, so far, when we said we go longer, we have gone from a 1 mile lateral or the 5,000-foot laterals to the 7,500-foot, and no, we have not really changed the recipe there The next well we have got on the drilling schedule is a 10,000-footer in Upton County and we're working on the design of that right now. So, there may be a slight change in the 10,000-foot design.

Okay, great, thanks, guys.

Thank you, our next question comes from the line of Ipsit Mohanty from Canaccord

Good morning.

Let me start off with the Texas -- with the Magellan Longhorn pipeline. If you could provide more color on the timeline, like is this current quarter be the first one to realize pricing or are we going to see a lag?

Yes, the pipeline started filling in April. And the producers that have committed the firm transportation to the line were notified late April and we nominated barrels starting in May. In May, will be the first time we realized the uptick in LLS versus WTI. And what Magellan is telling us is that there's three kind of milestone production points that they are going to reach.

The first is 75,000 barrels a day which they hope to reach, end of this month, early next month. And then they will go to 135,000 barrels, which is in the July time frame, and then they anticipate being at 225,000 barrels kind of in late October. And what they will do at each one of those milestones is that they will come back to the producers and they will increase the allotment up until, for Diamondback, up until we are at our 8000 barrels a day of firm transportation when they are at 225,000 barrels a day of full capacity.

Now Travis, on pricing, is that a spot pricing that you have fixed with them, or is it a fixed pricing? If you could talk about that a little bit?

It is simply a deduct. So we receive LLS pricing, less about $7 a barrel.

Got you. Great. And then a follow-up on the horizontal Wolfcamp wells in Midland and Upton. If you could talk -- do you plan to drill any laterals longer than the 7,500? And just approximately how many of them to test out the (inaudible) long laterals?

What we have seen, Ipsit, is that there is a cost efficiency as you increase the lateral length. And we have seen that when we went from the 5,000-foot laterals to 7,500-foot laterals. And as I just mentioned, we are getting ready to test our first 10,000-foot lateral in Upton County and we anticipate seeing that same cost efficiency as we add another 2,500 feet of lateral length.

Granted, every time you add lateral length, you increase risk a little bit, so that is kind of the offset there. In a general sense, we let our lateral lengths be dictated by our lease geometry. So, our sort of preferred lateral length is in that 7,500-foot to 8,000-foot range, because most of our leaseholds are kind of 3 miles standup sections and we can develop 3 miles with two 7,500-foot laterals.

Where we can now is rather than drill two short laterals, we are going to try to drill one long 10,000-foot lateral, and we think there is a material cost improvement, or a cost-efficiency improvement there. But we've got to get one on the board first. And so, when I look ahead for this year, I think we have got Russell, we have got roughly five 10,000-foot laterals on the board for the rest of this year. But, the first in Upton County is the one that we are really going to test.

Travis, you might have talked about this, but I assume your additional rig in the Wolfcamp will be in the Midland County?

That's a fair assumption.

And given what you have just seen with putting submersible pumps on these wells, are you going to do that across the board on all wells or is it a case-by-case basis?

Right now, my operations organization is saying they are liking what they see and it is probably going to be all future wells will go with the sub pumps.

Wonderful.

Our next question comes from the line of Jeffrey Connolly with Brean Capital. Your question please.

Good morning, guys. One quick follow-up on CapEx. The third horizontal rig, that is baked into the guidance too, right?

That's correct.

and then around the announcement of the S1, you guys mentioned potentially raising CapEx to accelerate horizontal drilling? Can you give us some idea what an accelerated horizontal program would look like?

That is one of those things that I mentioned earlier. In this quiet period with the SEC, I can't comment on any of that until we actually get effective and get out on the road with our story.

Okay. Thanks fine. Thank you very much. That is it for me.

You bet, thanks.

Our final question comes from the line of Matt Portillo from Tudor, Pickering. Your question please.

Good morning, guys.

Good morning, Matt.

Just a few quick questions for me. One of the interesting comments you just made was potentially drilling a longer 10,000-foot lateral versus two shorter 4,500-foot laterals. I was curious if you have guys have a rough kind of ASE estimate of what you would be looking for on the 10,000-foot lateral. Just trying to get a sense of, kind of, the potential improvement on capital efficiency.

Yes, we are putting the final touches on the ASE right now, but it is in the $9 million range. And as I reported, our current first-quarter performance on the shorter laterals were $6 million. So if you just look at those two end points, a $9 million, 10,000-footer, versus a $12 million for two, 5000-foot laterals. That is where you start seeing the economies of scale there. Which makes the risk profile worth probably taking.

Perfect. And then just on the Wolfberry, I was wondering if you could just give us an update on where you're AFE costs are coming in there? And do you guys continue to see some cost efficiencies you can ring out on the Wolfberry wells?

Yes, we're running about $2 million to $2.1 million right now on actuals. And we are picking up pennies right now on the vertical program. I will not say we will never be happy with cost performance in a general sense. We always strive to reduce costs. But we are pretty close to the edge right now.

Great. And then I know you guys are focusing, obviously, on the Wolfcamp horizontals and that has been covered in detail here. I was just curious on the Wolfberry, as we think about the 20-acre down spacing opportunity, I know that at time of the IPO that was something you may have been looking at late this year or early in 2014. I was wondering if that was still in the plans, and if you have seen any other offset operators testing some of the additional 20-acre down spacing that would give you confidence in limited and interference on the wells.

Yes, in our plans right now for this year we don't anticipate doing any 20-acre infill wells. In fact, most of the vertical program we will have in front of us, is just simply to hold acreage. But we are actively involved in conversations with some private operators around town that are active in down spacing, and we are in conversations with those guys, and in a general sense, the jury is still out on there.

But I think as we think about it, somewhere around an 80% reduction from the 40-acre well is reasonable. So, you will just have to do the economics on cost and recoveries to see if that is an economic venture. But it is not a decision we are faced with right now. It is still future economic inventory for our shareholders going forward. Right now we are drilling the highest rate of return investments we can and those are the Wolfcamp B horizontal wells.

Perfect, and just my last question. We have seen softness in the A&D market as of late with some failed private opportunities. And I assume that may provide you guys some opportunity to pick up additional leasehold acreage. Although we are clearly operating, it is still a hot market. Just wondering if you could give us any commentary on how you see the A&D market at the moment, and really the opportunities that you see for picking up incremental acreage within Midland or some of the other basins within the Permian.

You are right in your comment about the acreage being tightly held. It is fair for our shareholders to expect that Diamondback is involved in every negotiation or every conversation about acquisitions in the Midland basin. In terms of picking up acreage, I think I announced last quarter that we picked up about 2,500 acres and I think we've added about 150 acres to 200 acres just this quarter as well too. We are picking up parcels and they are both on acreage. And we are active in the game of the A&D arena, as well.

Thank you very much.

Thank you, this does conclude the question and answer session of today's program. I'd like to hand the program back to Travis Stice for concluding remarks.

Great. I know this is a busy time and a busy day for a lot of the equity analysts out there. I appreciate the attention this morning that Diamondback got. And also I appreciate everybody else that was on the call, as well, too, expressing your interest in Diamondback Energy. If you have got any questions, we are in our offices all week. We have got Adam Lawlis now and his contact information is on our website. So, if you have got any further questions reach out to Adam. Just really, thanks guys, for interest in Diamondback Energy and we look forward to having some more conversations with you guys in the future.